1. Field of the Invention
This invention relates to a process and system for reducing the sulfur content of sulfur-containing gaseous streams. In one aspect, this invention relates to the treatment of gaseous streams produced by gasification and combustion processes. In one aspect, this invention relates to the use of the basic UCSRP process for removal of sulfur from gaseous streams. In one aspect, this invention relates to the treatment of sulfur-containing gaseous streams to achieve ultra-low sulfur levels therein.
2. Description of Related Art
Conventional technology for removing H2S from natural gas and hydrocarbon process gas streams is to contact the process gas stream in a suitable mass transfer contacting device, usually a vessel fitted out with packing or contactor trays, for example, valve trays, with a chemical solvent, such as an amine solution at a specified strength of amine in water, usually 50% or less amine by weight, but dependent on the specific amine employed or a specific solvent. Such amines absorb acidic gases, CO2, and H2S, and similar acidic components, although the first two are the acidic components usually found in significant concentrations, and form a chemically bonded solution referred to as a rich or loaded amine. The rich or loaded amine is sent to be “stripped” or regenerated, sometimes by the application of heat from direct injection of steam into a second, separate amine contactor often referred to as the regenerator, stripper, or reboiler, but also by indirectly heating the rich solution in the reboiler located at the bottom of the stripper. Inert gases or gases not containing acidic components, such as nitrogen, may also be added to such strippers to promote the dissociation of the chemically bonded acidic components or allow the reactions to occur at lower temperatures. Vacuum may also be applied. After sufficient exposure to the vapor stream in the stripper, the now lean solution is cooled, usually by cross exchange with the feed to the stripper, so as to minimize the required heat duty of the overall system. The lean amine is then returned to the absorber.
The off-gases from the stripper are sent to a sulfur recovery unit, most often a Claus plant in which some of the gas is burned with air to create approximately 2:1 H2S/SO2 ratio in the gas at a temperature above 2500° F., resulting in the reaction2H2S+SO2=3S+2H2O  (1)occurring in the gas phase. The gas is then cooled, resulting in separation of up to about 70% of the sulfur in the feed as liquid elemental sulfur in the liquid phase. The gas is reheated and passed over a catalyst at 600° F. or thereabouts, resulting in the formation of additional elemental sulfur. The gas is then cooled again, resulting in further elemental sulfur recovery. This is repeated in a total of 2 to 4 such catalytic Claus reactors until about 97% of the sulfur has been removed. Further removal is limited by equilibrium and if additional sulfur needs to be removed, all of the sulfur-containing compounds may be converted to H2S over a catalyst. The H2S so formed is then separated from the gas with a second absorber/stripper and recycled to the Claus process. By such means, in excess of 99% of the sulfur can be recovered.
The steps subsequent to the Claus reactors and condensers are referred to as off-gas treating processes and “tail gas” treating processes. Various enhancements to these processes exist to achieve even higher recoveries when required. For smaller tonnages of sulfur in the feed gas, about 20 tons per day or less, liquid redox processes such as LO-CAT or STRETFORD®, or the CRYSTASULF® process, may instead be employed more economically. For even smaller tonnages on the order of 100 lbs/day or less, absorbent beds of iron containing materials or caustic impregnated carbon or zinc oxide, or liquid filled beds of triazine “scavengers” or other chemicals or caustic may be used at lower system cost than the liquid redox type processes.
Similarly, based on Hysys simulation data using DGM as the solvent to remove H2S from this specific feed gas (shown in Table 1), the product gas would contain about 60 ppmv SO2 if the reactor was operated at about 750 psia and a temperature of about 270° F. in an excess SO2 mode with about 2% excess SO2 (based on the total inlet stoichiometric SO2 requirement) in the effluent gas. If the SO2 level would have to be reduced to below 50 ppbv for specific downstream processing applications, it again would be necessary to add extra absorber/stripper operations using DGM or DEG solvents to further reduce the SO2 levels to below 5-10 ppmv, and to add extra units that use specific adsorbents, such as a slurry of alkaline sorbent (e.g., limestone or lime) or dry sodium bicarbonate, or an aqueous sodium hydroxide solution which are typically used commercially to treat the product gas for further reducing the SO2 level to below 50 ppbv. For large-scale commercial applications for gaseous streams containing relatively large levels of CO2, the net expense for the use of such adsorbents (that would react with SO2 as well as with CO2) would be relatively very high to achieve a SO2 specification of 50 ppbv or less.
The UCSRP (University of California Sulfur Recovery Process) concept for the removal of sulfur from natural gas and various gaseous streams is described in U.S. Pat. No. 7,381,393. In the UCSRP, hydrogen sulfide (H2S) is reacted with sulfur dioxide (SO2) to form sulfur in the presence of an organic liquid or solvent, preferably at temperatures above the melting point of sulfur in accordance with reaction (1). Typical solvents that may be used to facilitate this reaction include diethylene glycol methyl ether (DGM) or diethylene glycol (DEG) with a homogeneous catalyst such as 3-pyridyl methanol, collectively referred to as the “Solvent”. As portions of the feed H2S and SO2 dissolve in the solvent, they react to form sulfur which is essentially insoluble in the Solvent. Thus, the liquid sulfur product may be separated from the Solvent/gas mixture at the reactor outlet. U.S. Pat. No. 7,381,393 further teaches that the system may be operated in two modes—excess H2S mode or excess SO2 mode. In the excess H2S mode, H2S is present in stoichiometric excess (at about 5-20% excess relative to the SO2 fed to the reactor) for driving the reaction to completion with extinction of the SO2 resulting in a product gas containing some H2S. Similarly, in the excess SO2 mode, SO2 is present in stoichiometric excess resulting in a product gas containing some residual SO2 depending on the extent of excess SO2 used and the overall reaction kinetics. In the excess H2S mode, the solvent recirculation rate for the absorber/reactor is relatively much higher than in the excess SO2 mode because the solubility of H2S in DGM-type solvents is significantly lower than that of SO2.
The key problem of operation of the UCSRP in the excess SO2 mode for all reactor stages, especially for H2S-laden gaseous streams that contain relatively high levels of CO2, is the downstream removal of the residual SO2 to ultra-low levels, defined herein as less than about 50 ppbv, which is required for various processes for the production of key chemicals and liquid/gaseous fuels and other processes requiring ultra low levels of SO2 in the cleaned gas.
An example of the operation of an H2S-rich UCSRP-type absorber/reactor column is based on Hysys® simulation data using DGM as the solvent to remove H2S from a specific feed gas composition (containing about 6200 ppmv H2S) shown in Table 1. The product gas at the outlet of a UCSRP-type absorber/reactor would contain about 120 ppmv H2S if the reactor was operated (at about 750 psia and 270° F.) in the excess H2S mode with about 2% excess H2S (based on the total inlet H2S). If an H2S level below 50 ppbv were required for specific downstream processing applications (e.g., conversion of coal-derived syngas to chemicals or liquid fuels), it would be necessary to use either additional UCSRP absorber/reactors operating in the excess H2S mode or another sulfur removal technology (e.g., the CRYSTASULF process) to reduce the H2S level further to about 5-10 ppmv, both of which options add significant capital and operating costs to the process, followed by use of a guard-bed (e.g., ZnO based) to reduce the H2S level from 5-10 ppmv to below 50 ppbv. For typical large-scale commercial operations, such as the processing of coal-derived syngas for the production of clean liquid fuels, the operating expense for the guard-bed adsorbent would be quite prohibitive if the H2S level after the second processing step (e.g., the use of the CRYSTASULF process) is higher than 10 s of ppmv.
TABLE 1Typical Composition of Coal-Derived Syngas After Sour Shift and Water RemovalMol %CH40.08CO1.16CO240.11H255.46H2S0.62N20.75H2O1.02NH30.14Ar0.66Total100.00
In a typical integrated gasification combined cycle (MCC) process, a low-value fuel such as coal, petroleum coke, biomass or municipal waste is converted to a high-hydrogen synthesis gas (syngas) by gasification. The syngas is then used as the primary fuel for a gas turbine. However, the syngas from the gasification process contains a number of impurities, including sulfurous compounds such as H2S, which must be removed before the syngas can be burned in the gas turbine. One existing approach is to use SELEXOL® or a similar physical solvent process in a selective two-column configuration to remove the H2S as a dilute stream in co-absorbed CO2, referred to as an acid gas. This dilute (in H2S) acid gas stream has a low H2S concentration for most gasification feedstocks due to the insufficient selectivity of SELEXOL for removing H2S in a stream containing larger amounts of CO2. This necessitates flow schemes with H2S concentrator columns and pre-loading the solvent with CO2 to enable the use of the inexpensive Claus-type acid-gas cleanup approach.